The wellbores produced by directional drilling can vary from a vertical inclination to a horizontal inclination in an effort to hit the desired target. This may result in sharp curvatures of the wellbore and areas, known as doglegs, where the angle or curvature of the wellbore has significantly changed. The degree of the curvature and inclination of the wellbore may cause problems, particularly when combined with a non-rotating drill string used in directional drilling. The problems which may arise include orientation difficulties, damage to downhole drilling tools and tool failures. In addition, sticking or hangup of the drill string in the wellbore may occur, resulting in inconsistent penetration of the formation by the drilling bit.
The penetration of the drilling bit is directly related to that portion of the load of the drill string which is transmitted to the drilling bit. The load of the drill string is the net combination of the weight of the drill string and any further upward or downward external loads applied to the drill string: Those portions of the drill string located in the area of the dogleg, or in areas of the wellbore with substantial curvature, are most subject to sticking or hangups. Sticking of the drill string within the wellbore is friction related and often caused by differences between the hydrostatic and formation pressures and mud properties. Hangups are often caused by larger drilling tools in the drill string coming in contact with formation bridges or variances in the diameter of the wellbore. Rotating drill strings are less susceptible to sticking and hangup than non-rotating drill strings due to the nature of the friction forces involved as the drill string moves through the wellbore. Rotating drill strings involve kinetic friction forces while non-rotating drill strings involve static friction forces. Static friction forces are greater than kinetic friction forces.
Typically, during normal drilling operations, the load of the drill string causes the drill string to pass through the wellbore without significant sticking or hangup. However, as the drill string passes through the wellbore around a bend or dogleg area, the friction between the drill string and the wellbore increases above that encountered in normal drilling operations and eventually the drill string may stop sliding within the wellbore. If the drill string stops sliding and becomes suspended in a problem area, the load on the drilling bit, as provided through the drill string, lessens and results in a decreased penetration of the drilling bit. Eventually the drilling bit drills off any remaining load on the drilling bit provided through the drill string by drilling out the formation in front of it. This is referred to as "drilling off". With no further load being provided to the drilling bit by the drill string, the penetration of the drilling bit is reduced to nothing. As a result, the drilling bit speeds up and the drilling mud is simply circulated back to the surface. An immobilized drill string may become permanently stuck in the wellbore.
To overcome sticking or hangup of the drill string within the wellbore, an increased load must be applied to the drill string. When the increased load overcomes the static friction between the drill string and the wellbore, the drill string starts to move downward through the wellbore and may do so in a jerky or sudden fashion. Upon release of the stuck drill string, the static friction between the drill string and the wellbore becomes kinetic friction and the bit may be forced downward into the end of the wellbore. If this occurs, the increased load on the drill string may be directly transferred to the drilling bit. If an increase in the load on the drilling bit occurs suddenly enough, there may be a significant increase in resistance to the rotation of the drilling bit and the flow of the drilling mud through the drilling bit as the drilling bit is forced against the end of the wellbore. If the mud motor is incapable of developing sufficient torque to cause the drilling bit to continue to rotate under the conditions encountered, the bit will stop rotating and may become jammed. This, in turn, may cause the mud motor to stall and all further drilling operations to cease until the increased load on the drilling bit is released. The entire drill string may need to be lifted from the bottom of the wellbore to release the load on the drilling bit. In addition, the orientation of the drill string may need to be confirmed prior to resuming the drilling operation. As well, depending upon the severity of the increased load and the erratic movement of the drill string, damage may be caused to the drilling bit and the mud motor.
Many drilling tools have been developed to overcome some of the above noted problems associated with directional drilling. These tools include drilling jars, bumper subs, shock subs and stabilizers. Drilling jars are used to assist in the freeing of a drill string that has become lodged or stuck in the wellbore. Jarring may be applied in both an upward motion and downward motion. To jar in an upward motion, an upward force is applied to the drill string, placing the drilling jar in tension. When a preset triggering plateau is reached, the trigger releases and causes the drill string to be jarred upwards. To jar in a downward motion, a downward compression force is applied which places the drilling jar in compression. When a preset triggering plateau is reached, the trigger releases causing the drill string to be jarred downwards. Bumper subs are similarly used to free a drill string which has become stuck or hung up. Bumper subs are used to apply a downward force on the stuck portion of the drill string by using the weight of the drill string. Shock subs or shock absorbers are used to relieve stresses in the drill string caused by erratic drilling bit motion, such as compression and tension forces from bouncing of the drilling bit and vibrations. Shock subs absorb these loads on the drilling bit and thereby alleviate some of the stresses to the drill string. A typical shock sub is designed to allow for only a minimal amount of movement between the maximum compression and the maximum tension of the tool and in order to be effective, must be designed so that it is capable of absorbing further compressive forces in the drilling string even when the load of the drill string is the maximum load expected to be encountered during normal drilling operations. The result of this is that a shock sub must always run in at least a partially open position, even under the most demanding downhole conditions, or it ceases to have any utility as a shock absorbing tool. Stabilizers are used to assist in maintaining the drill string in a central position in the wellbore, controlling the wellbore diameter and controlling the wellbore angle. None of the existing drilling tools described above are directed at maintaining penetration of the drilling bit when the axial compressive load transmitted to the drilling bit is decreased due to sticking and hangup of the drill string.
In addition to the tools discussed above, U.S. Pat. No. 4,697,651 issued to Dellinger on Oct. 6, 1987 describes a method of drilling which is intended to address the problems associated with sticking or hangup of the drilling string encountered during directional drilling. This method utilizes an extension sub having both axially contracted and axially extended positions which provides weight to the drilling bit as it moves from a contracted to an extended position. The method includes a drilling stroke which is initiated by lifting the drilling bit about 30 feet above the wellbore bottom and then imparting both rotation and a rapid dynamic movement downward to the drilling bit so that the drilling bit impacts the wellbore bottom and thereby contracts the extension sub. Once the extension sub is contracted, it apparently becomes locked in the contracted position so that the drilling bit can then be raised off the wellbore bottom and oriented in the desired direction, following which the extension sub is released from its contracted position so that it can extend against the wellbore bottom, thus effecting the drilling stroke. Once the extension sub becomes extended, the drilling stroke is repeated. There are several disadvantages of the method described in U.S. Pat. No. 4,697,651. First, the drilling bit must be lifted from the wellbore bottom in order to orient the drilling bit prior to the drilling stroke, thus disrupting the drilling process. Second, the extension sub can only be contracted by imparting a rapid dynamic movement downwards from a significant distance above the wellbore bottom, resulting in high dynamic loading on the drill string and potential damage to the drilling bit and the mud motor. Third, the method is clearly not applicable to normal drilling operations, where the intent is to minimize erratic movement of the drill string in order to avoid wear and tear on the drilling equipment.
There is therefore a need in the industry for a tool for connection in a wellbore drill string for maintaining an amount of penetration of a drilling bit attached to the drill string when an axial compressive load applied through the tool to the drilling bit by the drill string during normal drilling operations is decreased.